We
measure spontaneous imbibition of aqueous (deionized water and
KCl solutions of various concentrations) and oleic (kerosene and iso-octane)
phases in several dry organic shale samples selected from two wells
drilled in the Horn River basin. We find that the imbibition rate
of aqueous phases is much higher than that of oleic phases even when
plotted versus scaling dimensionless time, contrary to capillary-driven
imbibition models. The observed difference is more pronounced in samples
with higher clay content. The results suggest that the excess water
intake is due to (1) the additional driving force provided through
water adsorption by clay minerals, and (2) the enhancement of sample
permeability through adsorption-induced microfractures.
Recent experiments show the strong water uptake of gas shales which are strongly oil-wet based on contact angle measurements. 1,2 Clay hydration, microfracture induction, lamination, and osmotic effect are collectively responsible for the excess water uptake. However, the previous measurements are not sufficient to isolate the above factors nor to explain why the bulk of shale samples can hardly imbibe the oil which completely spreads on their surface. To answer the remaining questions, we measure and compare spontaneous imbibition of oil and water into the crushed packs of the similar shales. In contrast to the intact samples, the crushed samples consistently imbibe more oil than water. The comparative study suggests that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil-wet. This argument is backed by complete spreading of oil on fresh surfaces of the rock. In contrast to the artificial pores of crushed rock, the existing pores of intact rock are already wetted by a film of water and/or covered by precipitated salt, which gives the pores a preference for water over oil. Furthermore, the presence of salt in the pore space provides an additional force for water uptake through an osmotic effect. This argument is backed by the observed reduction in shale alteration and water imbibition through increasing the salt concentration.
Organic shales are exposed to treatment fluids during
and after
hydraulic fracturing operations. The fluid–shale interaction
influences the petrophysical alteration of the fractured shale and
the fate of the fracturing fluid. We systematically measured the spontaneous
water and oil intake of five shale samples collected from the cores
of two wells drilled in the Horn River basin. The samples represent
three shale formations with different mineralogy and petrophysical
properties. We characterize the samples by measuring the porosity,
conducting X-ray diffraction, and interpreting the well logging data
and scanning electron microscopy images. The water intake is higher
than the oil intake for all samples. The excess water intake and the
physical alteration degree correlate with the shale mineralogy and
petrophysical properties. The ratio between the water and oil intake
is much higher than the ratio between the water and oil capillary
pressures, even for the non-swelling shales. The comparative study
indicates that the water intake of organic shales is controlled by
both adsorption and capillarity.
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